Automated reservoir navigation

ABSTRACT

Examples described herein provide a computer-implemented method for automated reservoir navigation that includes receiving a reference indicative of a reservoir architecture. The method further includes determining a discrepancy between a well plan and the reference. The method further includes evaluating the discrepancy relative to a discrepancy threshold. The method further includes, responsive to determining that the discrepancy fails to satisfy the discrepancy threshold, causing a bottom hole assembly to navigate based at least in part on the discrepancy.

CROSS-REFERENCE TO RELATED APPLICATIONS

This application claims the benefit of U.S. Provisional PatentApplication Ser. No. 63/326,217 filed Mar. 31, 2022, the disclosure ofwhich is incorporated herein by reference in its entirety.

BACKGROUND

Embodiments described herein relate generally to downhole explorationand production efforts in the resource recovery industry and moreparticularly to techniques for automated reservoir navigation.

Downhole exploration and production efforts involve the deployment of avariety of sensors and tools. The sensors provide information about thedownhole environment, for example, by collecting data about temperature,density, saturation, and resistivity, among many other parameters. Thisinformation can be used to control aspects of drilling and tools orsystems located in the bottom hole assembly, along the drillstring, oron the surface.

SUMMARY

In one exemplary embodiment, a computer-implemented method for automatedreservoir navigation is provided. The method includes receiving areference indicative of a reservoir architecture. The method furtherincludes determining a discrepancy between a well plan and thereference. The method further includes evaluating the discrepancyrelative to a discrepancy threshold. The method further includes,responsive to determining that the discrepancy fails to satisfy thediscrepancy threshold, causing a bottom hole assembly to navigate basedat least in part on the discrepancy.

In another exemplary embodiment a system includes a bottom hole assemblydisposed in a wellbore and a processing system for executing computerreadable instructions. The computer readable instructions control theprocessing system to perform operations. The operations includereceiving a reference indicative of a reservoir architecture. Theoperations further include determining an offset between a well plan andthe reference. The operations further include determining a relative dipbetween the well plan and the reference. The operations further includedetermining a drainage area between the well plan and the reference;evaluating the offset, the relative dip, and the drainage area relativeto respective offset, relative dip, and drainage area thresholds. Theoperations further include, responsive to determining that at least oneof the offset, the relative dip, and the drainage area fails to satisfyone or more of the respective offset, relative dip, or drainage areathresholds, causing the bottom hole assembly to navigate based at leastin part on at least one of the offset, the relative dip, or the drainagearea.

Other embodiments of the present invention implement features of theabove-described method in computer systems and computer programproducts.

Additional technical features and benefits are realized through thetechniques of the present invention. Embodiments and aspects of theinvention are described in detail herein and are considered a part ofthe claimed subject matter. For a better understanding, refer to thedetailed description and to the drawings.

BRIEF DESCRIPTION OF THE DRAWINGS

Referring now to the drawings wherein like elements are numbered alikein the several figures:

FIG. 1 depicts a cross-sectional view of a wellbore operation systemaccording to one or more embodiments described herein;

FIG. 2 depicts a block diagram of the processing system of FIG. 1 ,which can be used for implementing the present techniques hereinaccording to one or more embodiments described herein;

FIG. 3 depicts a block diagram of a system for automated reservoirnavigation according to one or more embodiments described herein;

FIG. 4A depicts a flow diagram of a method for automated targetdiscrepancy review according to one or more embodiments describedherein;

FIG. 4B depicts a flow diagram of a method for ad-hoc target discrepancyreview according to one or more embodiments described herein;

FIG. 5 depicts a flow diagram of a method for automated reservoirnavigation according to one or more embodiments described herein;

FIGS. 6A-6F depict schematic views of a well path according to one ormore embodiments described herein;

FIG. 7 depicts a wireframe of an interface for automated reservoirnavigation according to one or more embodiments described herein; and

FIGS. 8A and 8B depict a target line triggering approach according toone or more embodiments described herein.

DETAILED DESCRIPTION

Modern bottom hole assemblies (BHAs) are composed of several distributedcomponents, such as sensors and tools, with each component performingdata acquisition and/or processing of a special purpose. An example ofone type of data acquired can include electromagnetic data.

Wellbores are drilled into a subsurface to produce hydrocarbons and forother purposes. In particular, FIG. 1 depicts a cross-sectional view ofa wellbore operation system 100, according to aspects of the presentdisclosure. In traditional wellbore operations, logging-while-drilling(LWD) measurements are conducted during a drilling operation todetermine formation rock and fluid properties of a formation 4. Thoseproperties are then used for various purposes such as estimatingreserves from saturation logs, defining completion setups, etc. asdescribed herein.

The system and arrangement shown in FIG. 1 is one example to illustratethe downhole environment. While the system can operate in any subsurfaceenvironment, FIG. 1 shows a carrier 5 disposed in a borehole 2penetrating the formation 4. The carrier 5 is disposed in the borehole 2at a distal end of the borehole 2, as shown in FIG. 1 .

As shown in FIG. 1 , the carrier 5 is a drill string that includes abottom hole assembly (BHA) 13. The BHA 13 is a part of the operationsystem 100 and includes drill collars, stabilizers, reamers, and thelike, and the drill bit 7. In examples, the drill bit 7 is disposed at aforward end of the BHA 13. The BHA 13 also includes sensors 10 (e.g.,including, but not limited to, measurement tools 11) and electroniccomponents (e.g., downhole electronic components 9). The measurementscollected by the measurement tools 11 can include measurements relatedto drill string operations, for example. BHA 13 also includes a steeringtool configured to steer BHA 13 and drill bit 7 into a desireddirection. The steering tool may receive steering commands based onwhich it creates steering forces to push or point drill bit 7 into thedesired direction. Operation system 100 is configured to conductdrilling operations such as rotating the drill string and, thus, thedrill bit 7. A drilling rig 8 also pumps drilling fluid through thedrill string 5 in order to lubricate the drill bit 7 and flush cuttingsfrom the borehole 2. The measurement tools 11 and downhole electroniccomponents 9 are configured to perform one or more types of measurementsin an embodiment known as logging-while-drilling (LWD) ormeasurement-while-drilling (MWD) according to one or more embodimentsdescribed herein.

Raw data is collected by the measurement tools 11 and transmitted to thedownhole electronic components 9 for processing. The data can betransmitted between the measurement tools 11 and the downhole electroniccomponents 9 by an electrical conduit 6, such as a wire (e.g. apowerline) or a wireless link, which transmits power and/or data betweenthe measurement tools 11 and the downhole electronic components 9. Poweris generated downhole by a turbine-generation combination (not shown),and communication to the surface 3 (e.g., to a processing system 12) iscable-less (e.g., using mud pulse telemetry, electromagnetic telemetry,etc.) and/or cable-bound (e.g., using a cable to the processing system12, e.g. by wired pipes). The data processed by the downhole electroniccomponents 9 can then be telemetered to the surface 3 for additionalprocessing or display by the processing system 12.

Drilling control signals can be generated by the processing system 12(e.g., based on the raw data collected by the measurement tools 11) andconveyed downhole or can be generated within the downhole electroniccomponents 9 or by a combination of the two according to embodiments ofthe present disclosure. The downhole electronic components 9 and theprocessing system 12 can each include one or more processors and one ormore memory devices. In alternate embodiments, computing resources suchas the downhole electronic components 9, sensors, and other tools can belocated along the carrier 5 rather than being located in the BHA 13, forexample. The borehole 2 can be vertical as shown or can be in otherorientations/arrangements (see, e.g., FIG. 3A, FIG. 3B).

It is understood that embodiments of the present disclosure are capableof being implemented in conjunction with any other suitable type ofcomputing environment now known or later developed. For example, FIG. 2depicts a block diagram of the processing system 12 of FIG. 1 , whichcan be used for implementing the techniques described herein. Inexamples, processing system 12 has one or more central processing units21 a, 21 b, 21 c, etc. (collectively or generically referred to asprocessor(s) 21 and/or as processing device(s) 21). In aspects of thepresent disclosure, each processor 21 can include a reduced instructionset computer (RISC) microprocessor. Processors 21 are coupled to systemmemory (e.g., random access memory (RAM) 24) and various othercomponents via a system bus 33. Read only memory (ROM) 22 is coupled tosystem bus 33 and can include a basic input/output system (BIOS), whichcontrols certain basic functions of processing system 12.

Further illustrated are an input/output (I/O) adapter 27 and a networkadapter 26 coupled to system bus 33. I/O adapter 27 can be a smallcomputer system interface (SCSI) adapter that communicates with amemory, such as a hard disk 23 and/or a tape storage device 25 or anyother similar component. I/O adapter 27 and memory, such as hard disk 23and tape storage device 25 are collectively referred to herein as massstorage 34. Operating system 40 for execution on the processing system12 can be stored in mass storage 34. The network adapter 26interconnects system bus 33 with an outside network 36 enablingprocessing system 12 to communicate with other systems.

A display (e.g., a display monitor) 35 is connected to system bus 33 bydisplay adaptor 32, which can include a graphics adapter to improve theperformance of graphics intensive applications and a video controller.In one aspect of the present disclosure, adapters 26, 27, and/or 32 canbe connected to one or more I/O busses that are connected to system bus33 via an intermediate bus bridge (not shown). Suitable I/O buses forconnecting peripheral devices such as hard disk controllers, networkadapters, and graphics adapters typically include common protocols, suchas the Peripheral Component Interconnect (PCI). Additional input/outputdevices are shown as connected to system bus 33 via user interfaceadapter 28 and display adapter 32. A keyboard 29, mouse 30, and speaker31 can be interconnected to system bus 33 via user interface adapter 28,which can include, for example, a Super I/O chip integrating multipledevice adapters into a single integrated circuit.

In some aspects of the present disclosure, processing system 12 includesa graphics processing unit 37. Graphics processing unit 37 is aspecialized electronic circuit designed to manipulate and alter memoryto accelerate the creation of images in a frame buffer intended foroutput to a display. In general, graphics processing unit 37 is veryefficient at manipulating computer graphics and image processing and hasa highly parallel structure that makes it more effective thangeneral-purpose CPUs for algorithms where processing of large blocks ofdata is done in parallel.

Thus, as configured herein, processing system 12 includes processingcapability in the form of processors 21, storage capability includingsystem memory (e.g., RAM 24 and mass storage 34), input means such askeyboard 29 and mouse 30, and output capability including speaker 31 anddisplay 35. In some aspects of the present disclosure, a portion ofsystem memory (e.g., RAM 24 and mass storage 34) collectively store anoperating system to coordinate the functions of the various componentsshown in processing system 12.

According to examples described herein, techniques for automatedreservoir navigation are provided. During reservoir navigation (alsoreferred to as “geosteering”), it may be desirable to maintain a certaindistance between the BHA and a distinct formation feature, such as aformation boundary within formation 4, e.g. the boundary between twodifferent formations (e.g. sand and shale), an oil-water contact, or afluid-gas contact within the formation. A boundary between two differentformations (e.g. sand and shale) is a surface in the formation 4 wherethe two formations come into contact. Similarly, an oil-water contact ora fluid-gas contact is a surface in the formation 4 where oil and wateror fluid and gas come into contact in a formation or where oilsaturation, water saturation, and/or gas saturation have a distinctvalue, such as a pre-defined value. Typically, the oil-water contactdenotes a surface having oil above and water below and the fluid-gascontact denotes a surface having gas above and fluid below. In otherinstances, the contact between two fluids may be transitional in a waythat the change from one fluid type into another fluid type is notrepresentable by a sharp contrast but rather by a gradational change insaturation. Formation features like formation boundaries (e.g.boundaries between two different formations, oil-water contacts, orfluid-gas contacts) can vary in space and may not be plain areas.

In order to achieve optimal hydrocarbon recovery from a hydrocarbonreservoir, it may be desirable to drill a wellbore a desired distanceaway from a formation boundary. Accordingly, the techniques forautomated reservoir navigation described herein provide for steering aBHA at least in part based on metrics that can be used to cause the BHAto navigate relative to a reference associated with a reservoirarchitecture, such as a formation boundary, etc. Examples of suchmetrics include offset, relative dip, and drainage area. The “offset” isan offset between a well plan and the reference associated with thereservoir architecture. The “relative dip” is a relative dip between thewell plan and the reference associated with the reservoir architecture.The “drainage area” is a drainage area between the well plan and thereference associated with the reservoir architecture. One or moreembodiments described herein provide for determining these metrics(e.g., offset, relative dip, and drainage area) with respect to a wellplan (e.g., a prediction (extrapolated points) or a planned trajectory)and the reference associated with the reservoir architecture and usingthese metrics to make navigation decisions to cause the BHA to navigatethrough a formation.

Recent developments towards automating wellbore placement aim atnavigating a wellbore at an ideally constant target offset (distance)away from an oil-water contact. The oil-water contact is a specificincidence of a fluid or lithological boundary/reference, which can bemapped or tracked using an inversion approach on using resistivity data.Current approaches to automated wellbore placement cause undulatingtrajectories, which do not seem to be in phase with the oil-watercontact and can cause early water breakthrough due to the proposedtrajectory coming too close to the oil-water contact.

One or more embodiment described herein address these and othershortcomings of the prior art by using offset, relative dip, anddrainage area metrics to control a BHA. For example, the metrics can beused to cause the BHA to navigate based at least in part on one or moreof the offset, the relative dip, or the drainage area.

FIG. 3 depicts a block diagram of a system 300 for automated reservoirnavigation according to one or more embodiments described herein. Thesystem 300 can be performed using one or more engines, systems,components, etc. configured and arranged as shown, although otherconfigurations and arrangements are also possible. One or more of thevarious engines, systems, components, etc. described regarding FIG. 3can be implemented as instructions stored on a computer-readable storagemedium, as hardware modules, as special-purpose hardware (e.g.,application specific hardware, application specific integrated circuits(ASICs), application specific special processors (ASSPs), fieldprogrammable gate arrays (FPGAs), as embedded controllers, hardwiredcircuitry, etc.), or as some combination or combinations of these.According to aspects of the present disclosure, the engine(s) describedherein can be a combination of hardware and programming. The programmingcan be processor executable instructions stored on a tangible memory,and the hardware can include a processing device (e.g., the processor 21a of FIG. 2 ) for executing those instructions. Thus a system memory(e.g., the RAM 24 and/or the ROM 22 of FIG. 2 ) can store programinstructions that when executed by the processing device implement theengines described herein. Other engines can also be utilized to includeother features and functionality described in other examples herein.

A data acquisition system 320 acquires data from one or more sensors(e.g., the measurement tools 11) associated with the BHA 13. The datacan be in the form of real-time (or near-real-time) data. The dataacquisition system 320 provides the data as real-time (ornear-real-time) LWD/MWD data to the reservoir mapping engine 310. Thereservoir mapping engine 310 generates a reference for a reservoirarchitectural feature (e.g., oil-water contact, oil-gas contact,lithological boundary, e.g., a lithological caprock boundary, formationboundary or layer boundary, such as a boundary between layers withdifferent formation characteristics (e.g., different gamma activity,magnetic, electric, or acoustic properties, or other characteristicsthat may be measured or logged while drilling)). Generating thereference may include defining/determining one or more locations of thereservoir architectural feature. Locations of reservoir architecturalfeature may be measured (such as by a distance from the BHA on a wellpath) or may be interpolated or extrapolated based on measured locationsof reservoir architectural features. Defining/determining one or morelocations of a reservoir architectural feature may be done by utilizingone or more inversion methods known in the art. For example, one or morelocations of a reservoir architectural feature may be defined/determinedby modeling a measurement response of a sensor (e.g., a resistivitysensor, a gamma sensor, an acoustic sensor, etc.) for a hypotheticalposition of the reservoir architectural feature. The modeled measurementresponse is then compared with the actual measurement response of thesensor and, in case of a mismatch between the modeled and the actualmeasurement response (e.g., in case that the difference or the ratio ofthe modeled and the actual measurement response exceeds a predefinedthreshold), the hypothetical position of the reservoir architecturalfeature is varied or amended and a measurement response of the sensor ismodeled again with the varied or amended position of the reservoirarchitectural feature and compared to the actual measurement response ofthe sensor. This process is repeated until the mismatch of the modeledand the actual measurement response is acceptably low (e.g., below apredefined threshold). Those skilled in the art will appreciate that theinversion may utilize pre-knowledge of the reservoir such as, but notlimited to, position of faults, oil-water contact, layer boundaries,etc. Such pre-knowledge may come from pre-drilled wells orinvestigations from the earth's surface, such as surface seismicinvestigations. Pre-knowledge of the reservoir may be used to define thehypothetical position of the reservoir architectural feature or may beused to limit the range in which the reservoir architectural feature maybe varied during the inversion process. Formation evaluation (FE) loginterpretation is performed at the reservoir mapping engine 310, whichcan be guided, for example, by petrophysicist 301. Reservoir navigationservices (RNS) engineer 302 can review and approve the reference, whichis then input into the navigation engine 312. The navigation engine 312,which is described in further detail herein (see, e.g., FIGS. 5 and6A-6F), provides navigational information/instructions (e.g., actualposition, such as actual depth information, actual inclination, oractual azimuth of the BHA 13 or the drill bit 7 and/or target position,such as target depth information, target inclination or target azimuthof the BHA 13 or the drill bit 7, etc.). Operations (OPS) engineer 303can review and approve the navigational information/instructions usingthe navigation engine 312. The navigational information/instructions arethen provided to the dynamic trajectory design engine 314, whichcomputes and provides a well plan and constraints as well as welltargets (which can be reviewed and approved by well planner 304) to thedynamic trajectory control engine 316. Well targets (or simply targets)may include positions that the well trajectory is supposed to enter inthe future. For example, a target position may be defined in space atsome distance of drill bit 7 and the BHA 13 and is then steered to drillthrough that target position. Targets may also include one or moretarget positions in space or a continuous range of target positions inspace, for example when defined by a target line (for example a straighttarget line). In case of one or more discrete target positions, targetsmay be defined by their coordinates (e.g., x,y,z-coordinates, or depth,inclination, and azimuth). In case of a range of target positions inspace, targets may be defined by equations and their parameters (forexample, a straight target line may be defined by the coordinates of onetarget position on the straight target line and the target slope of thestraight target line). Targets may not only be defined with respect topositions but also with respect to other metrics (for example, withrespect to offset, relative dip, or drainage area). For example, atarget offset may be defined and the BHA 13 is then steered to drill ina way that the measured offset matches the target offset with apredefined accuracy (e.g., in a way that the difference and/or ratio oftarget offset and measured offset is below a predefined threshold). Asanother example, a target relative dip between a reference and the welltrajectory may be defined and the BHA 13 is then steered to drill in away that the measured relative dip matches the target relative dip witha predefined accuracy (e.g., in a way that the difference and/or ratioof target relative dip and measured relative dip is below a predefinedthreshold). As yet another example, a target drainage area between areference and the well trajectory may be defined and the BHA 13 is thensteered to drill in a way that the measured drainage area matches thetarget drainage area with a predefined accuracy (e.g., in a way that thedifference and/or ratio of target drainage area and measured drainagearea is below a predefined threshold). Directional driller 305 canreview and approve the well plan and constraints as well as welltargets. Once approved, the dynamic trajectory control engine 316 sendssteering downlinks with steering information/instructions to the BHA 13as encoded steering downlinks via downlinking system 318. Driller 306,in some cases, can reject the downlinks as shown in FIG. 3 .

The techniques described herein (see, e.g., the method 500 of FIG. 5 )can be implemented in the context of an automated wellbore placementservice, such as using the system 300 of FIG. 3 . Examples of operatingmodes for automated reservoir navigation advice are shown in FIGS. 4Aand 4B.

FIG. 4A depicts a flow diagram of a method 400 for automated targetdiscrepancy review according to one or more embodiments describedherein. At block 402, the system 300 monitors a distance to the nextconnection. That is, during the drilling process carrier 5 comprises aplurality of drill pipes. One or more drill pipes are typicallypre-connected to form a so-called stand. Stands will be consecutivelyadded to carrier 5 as drill bit 7 and BHA 13 progress into formation 4to form borehole 2. To add a stand to carrier 5, the drilling processneeds to be progressed such that the carrier 5 is almost completelylowered into borehole 2. Rotation of drill bit 7 and flow of drilling isthen halted to allow adding a new stand to carrier 5. This allows makinga connection between the new stand and the carrier 5 so that the newstand becomes part of carrier 5. Adding a stand by making a connectionbetween a new stand and carrier 5 is done every time the borehole 2 isdrilled further such that the carrier 5 is almost completely loweredinto the borehole. At block 404, the system 300 continuously monitors adiscrepancy between metrics (e.g., the difference or ratio of measuredoffset, relative dip, or drainage area and respective measured offset,relative dip, or drainage area). “Continuously monitoring” in thiscontext means performing periodically repeated measurements. When thedistance to the next connection falls under a preselected threshold,(for example, when the distance to the next connection is below 1 meter)and if the discrepancy between chosen metrics exceeds or falls below thepredefined thresholds, system 300 sends out a corresponding notificationso that the discrepancy can be reviewed at block 406 using a target toreference, offset, relative dip, and/or drainage area at block 408. Atdecision block 410, it is determined whether to change the well planbased on the evaluation at block 406, which can be checked andeventually confirmed or rejected by an engineer 412 (e.g., the RNSengineer 302 of FIG. 3 ). If the decision is not to change the wellplan, monitoring continues at block 402. If, however, it is decided atdecision block 410 to change the well plan, a new target can be definedat block 414, and a dynamic trajectory design can begin at block 414(see dynamic trajectory design engine 314 of FIG. 3 ).

FIG. 4B depicts a flow diagram of a method 420 for ad-hoc targetdiscrepancy review according to one or more embodiments describedherein. At block 422, the processing system 300 performs continuousdiscrepancy monitoring at block 422. It is then determined at decisionblock 424 whether the discrepancy exceeds or falls below predefinedthresholds for offset, relative dip, and/or drainage area based onvalues at block 426. If the discrepancy does not exceed or fall belowpredefined thresholds, monitoring continues at block 422. If, however,it is decided at decision block 424 that the discrepancy exceeds orfalls below threshold(s), the method proceeds to block 428 and an alertis issued. At block 430, new targets can be defined (e.g.,automatically, manually, etc.), and at block 432, a dynamic trajectorydesign can begin (see dynamic trajectory design engine 314 of FIG. 3 ).

FIG. 5 depicts a flow diagram of a method for automated reservoirnavigation according to one or more embodiments described herein. Themethod 500 can be performed by any suitable processing system downholeor on surface (e.g., the processing system 12, the downhole electroniccomponents 9, a cloud computing node of a cloud computing environment),any suitable processing device (e.g., one of the processors 21), and/orcombinations thereof or another suitable system or device. FIG. 5 is nowdescribed in more detail with reference to FIGS. 3 (as described above)and 6A-6F, which depict schematic views of a well path according to oneor more embodiments described herein.

The method 500 provides for monitoring metrics, such as the position ofa wellbore relative to a reservoir architecture, determining anydiscrepancy therebetween, and providing navigation advice to reduce thediscrepancy. This approach is applicable to multiple drilling scenarios,such as a change in an offset to a reference, a change in aninclination/relative dip between a reference and a well plan, a changein an offset and an inclination in upwards and downwards total verticaldepth (TVD) direction, a change in a lithology so that a reference ismissing for a section of a wellbore, stringer intervals, undulations andinclination changes, navigation along two references, and the like. Insome examples, the navigation advice is “stable advice” in that it holdsfor an elongated drilling distance. In some examples, frequentlyfluctuating advice is reduced so as to not overly trigger navigationadvice. In some implementations, the method 500 is applicable to agenerate navigation advice for a single reference. However, in someexamples, multiple references can be used.

Turning now briefly to FIG. 6A, a schematic view of a well path 601 anda reference 602 is provided. In this case, the reference is an oil-watercontact boundary, but it should be appreciated that other reservoirarchitectures are also possible. For example, reference 602 could be alayer boundary, such as a boundary between layers with differentformation characteristics (e.g., different gamma activity, magnetic,electric, or acoustic properties, or other characteristics that may bemeasured or logged while drilling). Notably, in the examples of FIGS.6A-6F, the well path 601 and the predicted well paths 601 a, 603 areone-dimensional structures in 3D space while the reference 602 is atwo-dimensional structure in 3D space. The well path 601 is determinedby one or more last directional surveys as known in the art, for exampledirectional surveys that may comprise measured directional information,such as azimuth, inclination and/or toolface and depth information, suchas total vertical depth or measured depth (distance from drilling rig 8along the borehole 2). Depending on the distance from the sensorsproviding the directional information to the drill bit 7, thedirectional information may be known as near-bit azimuth, near-bitinclination, etc. Directional surveys may be determined at discretelocations on well path 601 (indicated by black dots in FIGS. 6A-6F) ormay be determined continuously. If directional surveys are determined atdiscrete locations, well path 601 may be determined by interpolationbetween those discrete locations. Depending on the distance from thesensors providing the directional information to the drill bit 7, thedirectional information may be known as near-bit azimuth, near-bitinclination, etc. The well path 601 includes a well path 601 a that isdrilled after the last directional survey is determined. Further, theschematic view 600 includes a well path prediction 603. It should beappreciated that the well path 601 a and the well path prediction 603are both predictions. The well path 601 a is a prediction to the drillbit 7 at the time when the directional measurements are taken within BHA13 and the well path prediction 603 is a prediction of the well pathahead of the drill bit 7. In one or more examples, the well path 601 acan include a predicted well path from a sensor position within BHA 13to the position of drill bit 7 (point 604) and prediction ahead of bit(e.g., the well path prediction 603). The difference of well pathpredictions 601 a and 603 is that the well path that corresponds to wellpath prediction 601 a is already drilled although yet unknown while thewell path that corresponds to well path prediction 603 does not evenexist in the situations as shown in FIGS. 6 a -6F. Well path predictions601 a, 603 may be determined by extrapolating information of well path601 to point 604 or ahead of drill bit 7 or by modeling the predictedwell path 601 a, 603 by suitable models that are capable to predictbehavior of BHA 13 and predicted well path 601 a, 603 when applyingcertain steering parameter to BHA 13. A point 604 on the well path 601represents the position of drill bit 7. A sensor offset 605 represents adistance along the BHA 13 between a measurement point or sensor locationon the BHA 13 and the drill bit 7. The well path 601 a can also includean actual well path or a planned well path, in various embodiments.

With continued reference to FIG. 5 , at block 502, the processing system12, using the navigation engine 312, receives a reference (e.g., thereference 602) indicative of a reservoir architecture. For example, thereference indicative of a reservoir architecture may be an oil-watercontact, an oil-gas contact, a lithological boundary (e.g., alithological caprock boundary, a formation boundary or layer boundary,such as a boundary between layers with different formationcharacteristics (e.g., different gamma activity, magnetic, electric, oracoustic properties, or other characteristics that may be measured orlogged while drilling)). According to one or more embodiments describedherein, the reference 602 is determined from surface data and/ordownhole data. Those skilled in the art will appreciate that saidsurface data and/or downhole data may include data that is measured bysensors within BHA 13 and sensors that are included in drilling rig 8.Surface data and/or downhole data may also comprise pre-knowledge of thereservoir, such as but not limited to position of faults, oil-watercontact, layer boundaries, etc. Such pre-knowledge may come frompre-drilled wells or investigations from the earth's surface, such assurface seismic investigations. For example, the BHA 13 can include oneor more sensors (e.g., measurement tools 11 in BHA 13) to collect datadownhole in the borehole (or wellbore) 2. The data can be any suitabledata, such as lithology data, acoustic data, rheological data,resistivity data, or the like, or any combination thereof.

At block 504, the processing system 12, using the navigation engine 312,determines an offset (i.e., a distance) between a well plan, an actualwell path 601, or a predicted well path 601 a, 603 and the reference(e.g., the reference 602). With reference to FIG. 6B, the reference 602is an oil-water contact and offset 610 is shown as ΔOWC. The offsetrepresents a distance between a well path 601, a predicted well path 601a, 603, or a planned well path (e.g., a position on well path 601,predicted well path 601 a, 603, planned well path) and a reference(e.g., the reference 602). This approach is applicable to offset-typeuser scenarios, for example. The offset can be determined at ameasurement point (e.g., a sensor location) of the BHA 13, at the drillbit 7, at a defined distance ahead of the bit 7, or any other desiredposition along well path 601. For bit-ahead determination forprediction, an extrapolation technique, such as a linear regression canbe used. For example, commonly-owned U.S. patent application Ser. No.17/200,207 describes such an extrapolation technique and is incorporatedby reference herein in its entirety. Using the offset approach isapplicable whenever geology references from inversion and the wellboreshows a smooth, well-defined behavior, for example. According to anexample, a desired offset (or “offset threshold”) can be defined, suchas 3 meters.

With continued reference to FIG. 5 , at block 506, the processing system12, using the navigation engine 312, determines a relative dip betweenthe well plan (e.g., the well path 601) and the reference (e.g., thereference 602). As shown in FIG. 6C, the relative dip 620 (shown as “a”)represents the angular difference between the inclination of a reference602 and the inclination of well path 601, predicted well path 601 a,603, or planned well path applicable to inclination-change typescenarios, for example. The relative dip can be determined fromorientations/directions/slopes of the well path (e.g., the well path601, predicted well path 601 a, 603, or planned well path) and thereference (e.g., the reference 602) over regression intervals L2 622(corresponding to the distance between sensor and drill bit 7) and L3623 using, for example, linear regression. It is important to note thatthe determination of the relative dip 620 between well path 601,predicted well path 601 a, 603, or planned well path and reference 602cannot be made based on a single measurement of the distance from BHA 13to reference 602. To determine the inclination of reference 602, atleast two measurement of the distance from BHA 13 to reference 602 haveto be used to calculate inclination of reference 602 and relative dipbetween well path 601, predicted well path 601 a, 603, or planned wellpath and reference 602. For example, a range of measurements of thedistance from BHA 13 to reference 602 over a predefined interval ofreference 602 may be used to calculate inclination of reference 602 andrelative dip between well path 601, predicted well path 601 a, 603, orplanned well path and reference 602. By using the relative dip,better-behaving navigational advice can be provided because the adviceis based on trends as opposed to single offsets, for example. Accordingto an example, a desired relative dip (or “relative dip threshold”) canbe defined, such as +/−2 degrees.

With continued reference to FIG. 5 , at block 508, the processing system12, using the navigation engine 312, determines a drainage area 630between a well plan and the reference. With reference to FIG. 6D, thedrainage area 630 represents the distance between a well path (e.g., thewell path 601) and a geological reference (e.g., the reference 602)integrated over a certain (e.g. predefined) portion of well path 601 orpredicted well path 601 a, 603 to monitor an expected drainage behaviorof a well applicable to undulating/fluctuating/tortuous reference linescenarios. That is, over the predefined portion of well path 601 orpredicted well path 601 a, 603, the distance between well path 601 orpredicted well path 601 a, 603 and reference 602 will be measured andmultiplied with the distance of the sensor location to the previouslocation where the distance between well path 601 or predicted well path601 a, 603 and reference 602 was measured to determine a portion of thedrainage area 630. The distance between well path 601 or predicted wellpath 601 a, 603 and reference 602 may be the shortest distance betweenwell path 601 or predicted well path 601 a, 603 and reference 602 at thesensor location. However, other options to define the distance are alsopossible. For example, the distance between well path 601 or predictedwell path 601 a, 603 and reference 602 may be a difference between TVDof the well path 601 or predicted well path 601 a, 603 at the sensorlocation and the TVD of the reference 602 at a point that has the samehorizontal coordinates as the sensor location. Summing the portions ofthe drainage area 630 within the predefined portion of well path 601 orpredicted well path 601 a, 603 will then allow to determine the drainagearea 630. By this definition of the drainage area 630, the drainage area630 corresponds to the hatched area in FIGS. 6D-6E. The drainage area630 can be determined by summing the portions of the drainage area 630within the predefined portion of well path 601 or predicted well path601 a, 603 (e.g., within a predefined distance interval, such as 10meters, 30 meters, a stand, three stands, 100 meters, or even longer) L4634. According to an example, a desired drainage area (or “drainage areathreshold”) can be defined. Similar to the determination of the relativedip 620 between well path 601, predicted well path 601 a, 603, thedetermination of the drainage area 630 between well path 601, predictedwell path 601 a, 603, or planned well path and reference 602 cannot bemade based on a single measurement of the distance from BHA 13 toreference 602. To determine the drainage area 630, at least twomeasurement of the distance from BHA 13 to reference 602 are used tocalculate the drainage area 630 between well path 601, predicted wellpath 601 a, 603, or planned well path and reference 602. In someexamples, the predefined distance interval L4 634 can be based, forexample, on how undulating or tortuous the reference 602 is. Forexample, if a reference 602 is highly undulating (has a hightortuosity), the predefined distance interval L4 634 can be longercompared to a case when reference 602 is less undulating (has a smallertortuosity). Undulating behavior or tortuosity of reference 602 can bedetermined while drilling progresses and distance interval L4 634 can beadjusted while drilling based on the determined undulating behavior ortortuosity of reference 602. For example, if during drilling based onthe measurements of distance from BHA 13 to reference 602, it can bedetermined that the undulating behavior or tortuosity of reference 602increased (decreased) over a predefined interval of reference 602 (suchas over the predefined distance interval L4 634, for example), thepredefined distance interval L4 634 can be increased (decreased) toadapt to the determined undulating behavior or tortuosity of reference602. This provides for making navigational corrections when significantdeviations occur (e.g., when the measured values exceed or fall belowtheir corresponding thresholds) while providing for stability whennavigating along smaller-scale undulating references (e.g., when themeasured values do not exceed or fall below their correspondingthreshold(s)).

According to one or more embodiments described herein, as shown in FIG.6E, a lower bound 640 can be set for reference 602 (e.g., undulating ortortuous reference 602) to provide for a fixed distance (e.g., minimumor maximum distance between the reference 602 and well path 601,predicted well path 601 a, 603, or planned well path over a predefinedinterval of the reference 602 and well path 601, predicted well path 601a, 603, or planned well path) when determining the drainage area 630.The lower bound 640 can be a horizontal, for example a horizontal at adistance from the sensor location that corresponds to a smallest orlargest measured distance from sensor location to reference 602 along apredefined portion of well path 601 a, or a percentage of thesmallest/largest measured distance from sensor location to reference 602along a predefined portion of well path 601 a, for example. Thisrepresents the lowest bound of the drainage area. This approach isbeneficial for undulating or tortuous references 602 by providing that aminimum distance is maintained between the reference 602 and the wellpath 601, predicted well path 601 a, 603, or planned well path.

As shown in FIG. 6F, the offset 610, relative dip 620, and drainage area630 determinations described with respect to blocks 504, 506, and 508 ofFIG. 5 are applicable in scenarios with multiple references. Forexample, FIG. 6F shows the well path 601 and two references: 650 a and650 b. In this example, the reference 650 a is a lithological boundarythat also represents an oil-gas contact and the reference 650 b is aboundary of oil-water contact. In such a scenario, a first offset, afirst relative dip, and a first drainage area may be determined withrespect to the first reference 650 a and a second offset, a secondrelative dip, and a second drainage area may be determined with respectto the second reference 650 b. In block 512 (as described below) BHA 13may then be navigated based on one or more of the first and secondoffset, first and second relative dip, and first and second drainagearea.

With continued reference to FIG. 5 , at block 510, the processing system12 using the navigation engine 312, evaluates the offset, the relativedip, and the drainage area relative to respective offset, relative dip,and drainage area thresholds. For example, the offset is compared to theoffset threshold, the relative dip is compared to the relative dipthreshold, and the drainage area is compared to the drainage areathreshold. As an example, the offset is determined not to satisfy theoffset threshold when the offset exceeds or falls below the offsetthreshold. It is noted that a threshold can be a discrete value or arange of values, e.g. a plurality of discrete values or an interval ofvalues. As another example, the relative dip is determined not tosatisfy the relative dip threshold when the relative dip falls outsidean angular range defined by the relative dip threshold. As yet anotherexample, the drainage area is determined not to satisfy the drainagearea threshold when the drainage area exceeds or falls below thedrainage area threshold.

When one or more of the thresholds are not satisfied, it may bedesirable to cause the BHA 13 to navigate differently, such as to changeits position relative to the well path 601, predicted well path 601 a,603, or planned well path. At block 512, responsive to determining thatat least one of the offset, the relative dip, and the drainage areafails to satisfy one or more of the respective offset, relative dip, ordrainage area thresholds, the processing system 12 (e.g., using one ormore of the navigation engine 312, the dynamic trajectory design engine314, the dynamic trajectory control engine 316, and/or the downlinkingsystem 318) causes the BHA 13 to navigate based at least in part on atleast one of the offset, the relative dip, or the drainage area. Thetrajectory control engine 316 can be a proportional integral derivativecontroller, in various embodiments. Alternatively, the processing system12 can include a proportional integral derivative controller forcontrolling the relative dip and/or the drainage area. For example, ifat block 510 it is determined that the offset threshold is not satisfied(e.g., the determined offset from block 504 exceeds the offsetthreshold), the BHA 13 may be caused to navigate closer to the referenceto reduce the offset. Similarly, if at block 510 it is determined thatthe relative dip threshold is not satisfied (e.g., the determinedrelative dip from block 506 falls outside an angular range defined bythe relative dip threshold), the BHA 13 may be caused to navigate toreduce the relative dip. If at block 510 it is determined that thedrainage area threshold is not satisfied (e.g., the determined drainagearea from block 508 exceeds the drainage area threshold), the BHA 13 maybe caused to navigate closer to the reference to reduce the drainagearea. Combinations of these are also possible. As an example, two oreven three of the metrics (e.g., offset, relative dip, and drainagearea) may exceed their respective thresholds. In such cases, the BHA 13may be caused to navigate to satisfy each of the metrics. Causing theBHA 13 to navigate can include generating a steering instruction andsending the steering instruction via telemetry to BHA 13 (e.g., as asteering downlink via downhole telemetry to the BHA 13).

Additional processes also may be included, and it should be understoodthat the process depicted in FIG. 5 represents an illustration, and thatother processes may be added or existing processes may be removed,modified, or rearranged without departing from the scope of the presentdisclosure. According to one or more embodiments described herein, themethod 500 is applicable to non-geometric references for lower-tierreservoir navigation services automation. An example of such a low-tierservice includes navigating along simple formation evaluation (FE)property such as a gamma ray value or a resistivity value. Thenavigation advice considers defining a reference FE value (such as 30API GR value), then monitoring a log (Gamma ray log, for example), andadjusting the well path towards meeting the Gamma ray value.

FIG. 7 depicts a wireframe of an interface 700 for automated reservoirnavigation according to one or more embodiments described herein. Theinterface 700 includes an offset display portion 710 that shows thedetermined/calculated offset 711 and the offset threshold 712. Theinterface 700 further includes a relative dip display portion 720 thatshows the determined/calculated relative dip 721 and the relative dipthreshold 722. The interface 700 further includes a drainage areadisplay portion 730 that shows the determined/calculated drainage area731 and the drainage area threshold 732. The interface 700 also includescontrols (e.g., control mechanisms) for controlling the offset (control713), the relative dip (control 723), and the drainage area (control733). The controls 713, 723, 733 are controllable by a user to adjustthe respective offset threshold 712, the relative dip threshold 722, andthe drainage area threshold 732. The interface also includes a well pathdisplay portion 740 that provides a schematic illustration of the BHA13, the well path (601, 601 a, 603) or a planned well path, thereference (602), and the metrics (e.g., offset, relative dip, drainagearea). The display portion 740 can display, for example, one or more ofFIGS. 6A-6F or other suitable schematics.

FIGS. 8A and 8B depict a target line triggering approach 800 accordingto one or more embodiments described herein. In this example, a targetline is shown that is continuously updated for new measurement points(e.g., at each point in time in which a measurement is taken by themeasurement tools 11). The target line may be defined and updated basedon a location of a reference, such as reference 602 in FIGS. 6A-6F. Forexample, the target line may be defined and updated to be at a fixeddistance to a reference or even parallel to a reference, such asreference 602. Triggers are implemented to indicate when to makenavigational corrections. For example, triggers are computed bycomparing the well path with a latest target line. The target line is aline that the well trajectory is supposed to approach and then follow.It may be defined with reference to the reservoir architecture (e.g.,oil-water contact), such as by a predefined offset from or a desireddistance to the reference (e.g., determined relative to total verticaldepth). Triggers are used to initiate causing the BHA to navigate (see,e.g., blocks 510, 512 of FIG. 5 ).

FIG. 8A shows the example target line trigger approach 800 occurring ata first time (i.e., t₁), and FIG. 8B shows the approach 800 at a secondtime (i.e., t₂).

As shown in FIG. 8A, the approach 800 includes a current well path 801having proceeded from a last survey point 802. The BHA 13 follows alongthe current well path 801 (including well path prediction as describedwith respect to FIGS. 6A-6F), and a measurement point for the BHA 13(such as a sensor location as described herein) is disposed at point d₁803 along the well path 801 at the first time (i.e., t₁). It should beappreciated that the point d₁ 803 represents a distance along the wellpath 801 from a predefined reference point on well path 801 (e.g., thesurface 3, the last survey point 802, or any other suitable referencepoint on well path 801).

The BHA 13 is being steered relative to an active target line 804established relative to an active target point 805. The active targetline 804 has a slope and an inclination that are related to each otherand passes through the active target point 805. The BHA 13 is beingnavigated to meet the active target line 804 as shown to define anactive well plan (or planned well path) 806. Well plan 806 may bedefined by taking the steering capability into account. For example, ifthe buildup rate of BHA 13 is limited by a maximum buildup rate (e.g.,10°/100 ft), the curvature of well plan 806 may be limited to thatmaximum buildup rate. The point 807 represents the point where theactive target line 804 is expected to meet the active well plan 806.This is referred to as a transition point to the planned tangent. Thepoint 807 is an anticipation length 808 away from the point d₁ 803(e.g., along the active well plan/planned well path 806).

At a next measurement time (e.g., at the second time (i.e., t₂)), a nextmeasurement is taken (e.g., by the measurement tools 11 in BHA 13). Thatis, with reference to FIG. 3 , the data acquisition system 320 receivesreal-time data from the BHA 13 and passes it to the navigation engine312 (such as via the reservoir mapping engine 310 as shown). Forexample, at the second time (i.e., t₂), a second measurement of thedistance from BHA 13 to reference (such as reference 602 in FIGS. 6A-6F,not shown in FIGS. 8A, 8B) may be taken and may be used to determine anew inclination of the reference, a new relative dip between well path801/well plan 806 and reference, and/or a new drainage area. As can beseen in FIG. 8B, the BHA 13 has progressed to a point d₂ 810.

As shown, at the second time t₂, the active target line 804 of the firsttime t₁ and the active target point 805 of the first time t₁ are aprevious target line 804 and a previous target point 805, respectively,and have been replaced by a new active target line 814 and a new activetarget point 815. The definition of new target line 814 and/or newtarget point 815 may be based on one or more of the determination of thenew inclination of the reference, the new relative dip between well path801/well plan 806 and reference, and/or the new drainage area. The BHA13 (e.g., a sensor location on BHA 13) is, in FIG. 8B, a newanticipation length 818 away from the new transition point 817 (i.e.,the transition point to the planned tangent).

Re-planning or navigating (e.g., sending a navigational command to theBHA 13 to cause the BHA 13 to navigate) can be based on one or more ofthe offset, the relative dip, and/or the drainage area. The relative dipmay be defined with respect to the reference (such as reference 602 inFIGS. 6A-6F) or with respect to the target lines (804, 814). That is,the relative dip may be defined as the difference between inclinationsof well path 601, 601 a, 603, or planned well path and the reference 602or may be defined as the difference between inclinations of well path801 or planned well path 802 and target line 804. For example, if therelative dip 821 at the new anticipation length 818 is greater than therelative dip threshold, the BHA 13 may be caused to navigate differently(e.g., to correct the relative dip). As another example, if the offset(e.g., the delta TVD 820) at the new anticipation length 818 is greaterthan the offset threshold, the BHA 13 may be caused to navigatedifferently (e.g., to correct the offset). The drainage area can beused, in another example, to cause the BHA 13 to navigate differently,such as if the drainage area exceeds the drainage area threshold. Itshould be appreciated that other trigger events can be used to initiateor trigger navigation instructions/commands being downlinked to the BHA13.

Example embodiments of the disclosure include or yield various technicalfeatures, technical effects, and/or improvements to technology. Exampleembodiments of the disclosure provide technical solutions for automatedreservoir navigation. These technical solutions collect and analyzelarge volumes of data collected in wellbore by a measurement devicedisposed in a bottom hole assembly, then evaluate the data to determinewhen to cause the BHA to navigate based on the collected data. The largevolume of data, complexity of the performing evaluation(s), and thereal-time or near-real-time nature of adjusting the trajectory of thebottom hole assembly cannot practically be performed in the human mind.Moreover, by controlling the BHA using the collected data and comparingto thresholds for determining when to make navigation determinations,one or more embodiments described herein improve the operation of theBHA and the drilling of the wellbore by reducing the frequency of adviceso as to not overly trigger navigation advice, which could causemistrust by users and create poor wellbores. Thus, the techniquesdescribed herein represent an improvement to geosteering technologies.Accordingly, drilling decisions can be made more accurately and faster,thus improving drilling efficiency, reducing non-production time,improving hydrocarbon recovery, and the like. Specifically, geosteeringis improved by acquiring and maintaining a desired position of the BHArelative to a reference. This increases hydrocarbon recovery from ahydrocarbon reservoir compared to conventional techniques.

Set forth below are some embodiments of the foregoing disclosure:

Embodiment 1: A method for automated reservoir navigation is disclosed.The method includes receiving a reference indicative of a reservoirarchitecture; determining a first distance between a well path and thereference and a second distance between the well path and the reference;determining a discrepancy based on the first distance and the seconddistance; and causing a bottom hole assembly to navigate based at leastin part on the discrepancy.

Embodiment 2: A method according to any prior embodiment, wherein thediscrepancy is indicative of at least one of an offset between the wellpath and the reference, a relative dip between the well path and thereference, or a drainage area between the well path and the reference.

Embodiment 3: A method according to any prior embodiment, wherein thewell path is based on extrapolated points.

Embodiment 4: A method according to any prior embodiment, wherein thereference is based at least in part on at least one of data selectedfrom the group consisting of lithology data, acoustic data, rheologicaldata, electromagnetic data, and resistivity data.

Embodiment 5: A method according to any prior embodiment, wherein theoffset is determined relative to a measurement point of the bottom holeassembly, at a drill bit of the bottom hole assembly, or a defineddistance ahead of the drill bit.

Embodiment 6: A method according to any prior embodiment, whereindetermining the offset relative to the defined distance ahead of thedrill bit is based at least in part on an extrapolation technique.

Embodiment 7: A method according to any prior embodiment, wherein therelative dip is determined from an orientation, a direction, or a slopeof the well path and the reference over an interval of the well path.

Embodiment 8: A method according to any prior embodiment, wherein thedrainage area is determined by summing a plurality of drainage areaportions over an interval of the well path wherein the drainage portionsare calculated by multiplying a distance between the well path and thereference with a distance along the well path.

Embodiment 9: A method according to any prior embodiment, wherein theinterval is set based on how undulating or constant the reference is.

Embodiment 10: A method according to any prior embodiment, furthercomprising providing an interface, wherein the interface presents theoffset, the relative dip, and the drainage area and a control mechanismto enable controlling the bottom hole assembly.

Embodiment 11: A system for automated reservoir navigation is disclosed.The system includes a bottom hole assembly disposed in a wellbore; and aprocessing system for executing computer readable instructions, thecomputer readable instructions controlling the processing system toperform operations including: receiving a reference indicative of areservoir architecture; determining at least one of a relative dipbetween the well path and the reference and a drainage area between thewell path and the reference; and causing the bottom hole assembly tonavigate based at least in part on at least one of the relative dip, orthe drainage area.

Embodiment 12: A system according to any prior embodiment, wherein thewell path is based on extrapolated points.

Embodiment 13: A system according to any prior embodiment, wherein thereference is based at least in part on at least one of data selectedfrom the group consisting of lithology data, acoustic data, rheologicaldata, and resistivity data.

Embodiment 14: A system according to any prior embodiment, wherein theoffset is determined relative to a measurement point of the bottom holeassembly, at a drill bit of the bottom hole assembly, or a defineddistance ahead of the drill bit.

Embodiment 15: A system according to any prior embodiment, whereindetermining the offset relative to the defined distance ahead of thedrill bit is based at least in part on an extrapolation technique.

Embodiment 16: A system according to any prior embodiment, wherein therelative dip is determined from an orientation, a direction, or a slopeof the well path and the reference over an interval.

Embodiment 17: A system according to any prior embodiment, wherein thedrainage area is determined by summing a plurality of drainage areaportions over an interval of the well path wherein the drainage portionsare calculated by multiplying a distance between the well path and thereference with a distance along the well path.

Embodiment 18: A system according to any prior embodiment, wherein theinterval is set based on how undulating or constant the reference is.

Embodiment 19: A system according to any prior embodiment, wherein theoperations further include providing an interface, wherein the interfacepresents at least one of the relative dip, and the drainage area and acontrol mechanism to enable controlling the bottom hole assembly.

Embodiment 20: A system according to any prior embodiment, wherein theprocessing system comprises a controller that controls the relative dipor the drainage area.

The use of the terms “a” and “an” and “the” and similar referents in thecontext of describing the present disclosure (especially in the contextof the following claims) are to be construed to cover both the singularand the plural, unless otherwise indicated herein or clearlycontradicted by context. Further, it should further be noted that theterms “first,” “second,” and the like herein do not denote any order,quantity, or importance, but rather are used to distinguish one elementfrom another. The modifier “about” used in connection with a quantity isinclusive of the stated value and has the meaning dictated by thecontext (e.g., it includes the degree of error associated withmeasurement of the particular quantity).

The teachings of the present disclosure can be used in a variety of welloperations. These operations can involve using one or more treatmentagents to treat a formation, the fluids resident in a formation, awellbore, and/or equipment in the wellbore, such as production tubing.The treatment agents can be in the form of liquids, gases, solids,semi-solids, and mixtures thereof. Illustrative treatment agentsinclude, but are not limited to, fracturing fluids, acids, steam, water,brine, anti-corrosion agents, cement, permeability modifiers, drillingmuds, emulsifiers, demulsifiers, tracers, flow improvers etc.Illustrative well operations include, but are not limited to, hydraulicfracturing, stimulation, tracer injection, cleaning, acidizing, steaminjection, water flooding, cementing, etc.

While the present disclosure has been described with reference to anexemplary embodiment or embodiments, it will be understood by thoseskilled in the art that various changes can be made and equivalents canbe substituted for elements thereof without departing from the scope ofthe present disclosure. In addition, many modifications can be made toadapt a particular situation or material to the teachings of the presentdisclosure without departing from the essential scope thereof.Therefore, it is intended that the present disclosure not be limited tothe particular embodiment disclosed as the best mode contemplated forcarrying out this present disclosure, but that the present disclosurewill include all embodiments falling within the scope of the claims.Also, in the drawings and the description, there have been disclosedexemplary embodiments of the present disclosure and, although specificterms can have been employed, they are unless otherwise stated used in ageneric and descriptive sense only and not for purposes of limitation,the scope of the present disclosure therefore not being so limited.

What is claimed is:
 1. A method for automated reservoir navigation, themethod comprising: receiving a reference indicative of a reservoirarchitecture; determining a first distance between a well path and thereference and a second distance between the well path and the reference;determining a discrepancy based on the first distance and the seconddistance; and causing a bottom hole assembly to navigate based at leastin part on the discrepancy.
 2. The method of claim 1, wherein thediscrepancy is indicative of at least one of an offset between the wellpath and the reference, a relative dip between the well path and thereference, or a drainage area between the well path and the reference.3. The method of claim 1, wherein the well path is based on extrapolatedpoints.
 4. The method of claim 1, wherein the reference is based atleast in part on at least one of data selected from the group consistingof lithology data, acoustic data, rheological data, electromagneticdata, and resistivity data.
 5. The method of claim 1, wherein the offsetis determined relative to a measurement point of the bottom holeassembly, at a drill bit of the bottom hole assembly, or a defineddistance ahead of the drill bit.
 6. The method of claim 5, whereindetermining the offset relative to the defined distance ahead of thedrill bit is based at least in part on an extrapolation technique. 7.The method of claim 1, wherein the relative dip is determined from anorientation, a direction, or a slope of the well path and the referenceover an interval of the well path.
 8. The method of claim 1, wherein thedrainage area is determined by summing a plurality of drainage areaportions over an interval of the well path wherein the drainage portionsare calculated by multiplying a distance between the well path and thereference with a distance along the well path.
 9. The method of claim 8,wherein the interval is set based on how undulating or constant thereference is.
 10. The method of claim 1, further comprising providing aninterface, wherein the interface presents the offset, the relative dip,and the drainage area and a control mechanism to enable controlling thebottom hole assembly.
 11. A system for automated reservoir navigation,the system comprising: a bottom hole assembly disposed in a wellbore;and a processing system for executing computer readable instructions,the computer readable instructions controlling the processing system toperform operations comprising: receiving a reference indicative of areservoir architecture; determining at least one of a relative dipbetween the well path and the reference and a drainage area between thewell path and the reference; and causing the bottom hole assembly tonavigate based at least in part on at least one of the relative dip, orthe drainage area.
 12. The system of claim 11, wherein the well path isbased on extrapolated points.
 13. The system of claim 11, wherein thereference is based at least in part on at least one of data selectedfrom the group consisting of lithology data, acoustic data, rheologicaldata, and resistivity data.
 14. The system of claim 11, wherein theoffset is determined relative to a measurement point of the bottom holeassembly, at a drill bit of the bottom hole assembly, or a defineddistance ahead of the drill bit.
 15. The system of claim 14, whereindetermining the offset relative to the defined distance ahead of thedrill bit is based at least in part on an extrapolation technique. 16.The system of claim 11, wherein the relative dip is determined from anorientation, a direction, or a slope of the well path and the referenceover an interval.
 17. The system of claim 11, wherein the drainage areais determined by summing a plurality of drainage area portions over aninterval of the well path wherein the drainage portions are calculatedby multiplying a distance between the well path and the reference with adistance along the well path.
 18. The system of claim 17, wherein theinterval is set based on how undulating or constant the reference is.19. The system of claim 11, wherein the operations further compriseproviding an interface, wherein the interface presents at least one ofthe relative dip, and the drainage area and a control mechanism toenable controlling the bottom hole assembly.
 20. The system of claim 11,wherein the processing system comprises a controller that controls therelative dip or the drainage area.